Selective zonal testing using a coiled tubing deployed submersible pump

ABSTRACT

An apparatus for measuring a property of a formation comprising a coiled tubing unit having one or more downhole sensors capable of being lowered into a wellbore, a submersible pump capable of being lowered into a wellbore by the coiled tubing unit, means to power the submersible pump, and a packer lowered into the wellbore by the coiled tubing unit to isolate a formation. A method of servicing a hydrocarbon well using one or more sensors, one or more packers, and a submersible pump, all lowered on coiled tubing into a well that penetrates a predetermined formation; and using surface well testing equipment, determining a property of a formation while flowing the well assisted by the submersible pump and using flow data measured using the surface well testing equipment integrated with pressure data measured using the one or more sensors lowered into the well penetrating the formation on the coiled tubing; treating the formation by pumping fluid into the formation using the coiled tubing; and repeating the determining a property of the formation while flowing the well as described above, wherein the coiled tubing remains deployed within the well throughout the determining, treating, and repeating the determining processes.

FIELD OF THE INVENTION

This invention is generally related to the testing of hydrocarbon wells,and more particularly to methods and apparatus associated with thetesting of hydrocarbon wells that utilize a submersible pump deployed oncoiled tubing to transport the hydrocarbons from the formation up thewellbore.

BACKGROUND OF THE INVENTION

When a well is producing hydrocarbons to surface and its performance isnot as expected, the well is often tested to determine the directcausation of this lack of flow rate. This is normally characterized by adimensionless factor called skin, which quantifies the productionefficiency of a formation. The wellbore damage or flow restriction mustthen be assessed to determine an appropriate method to treat the damageeffectively. This damage can be the result of many conditions such asbut not limited to solid or mud-filtrate invasion, perforating debris,inadequate perforations, near or far wellbore damage and lowpermeability formations. Stimulation methods such as fracturing oracidizing are typically used to attempt to increase formationproductivity. Another test may be performed after stimulation toevaluate the effectiveness of the treatment.

To properly treat a damaged well, we first need to understand the originand nature of the damage. One way to achieve this is by analyzing welltest data.

One of the preferred methods used in well test interpretation ispressure transient analysis (also called “PTA”). This method combinesflow rate and bottomhole pressure measurements obtained by flowing thewell through instruments at the surface and by recording the bottomholepressure with the well shut-in. Both measurements (flowing and shut-in)are recorded at one or a plurality of time periods depending on thecomplexity of the study. The pressure and pressure derivative curves arecompared to known type-curves to determine the skin and permeability.After the treatment is formulated and executed, a post stimulation testmay be conducted to record a final skin.

To better understand the reservoir using surface well testing and coiledtubing stimulating services to optimize production, the two services canbe integrated. The ability to evaluate, treat, and test a well has beena long desired industry goal.

This can be accomplished by using enhanced Coiled Tubing Services as themeans to stimulate and test a well. The coiled tubing is run down thewell with a downhole assembly comprising one or more sensors and anyother equipment and instruments needed during the well test. A packer(seal cups, swab cup assemblies or set of packers) included in thecoiled tubing bottomhole assembly is normally set above the formation,in the case of one packer/seal cup or straddling the formation in thecase of two packers, one top packer and a lower swab cup or two swab cupassemblies. Included in this bottomhole assembly (referred to as a “BHA”and also known as a downhole assembly) are one or more gauges that areused to acquire the downhole pressure and temperature.

The coiled tubing can now transport fluids to and from the well(allowing acidizing or fracturing fluids to be pumped into the well andallowing reservoir fluids from the well to flow to the surface, etc.)with the assistance of surface equipment where the flow rate ismeasured. To test, stimulate, and test again all through coiled tubingoffers a great reduction in rig time and a much needed method tounderstand complex wells.

The use of coiled tubing as a mean to well test a particular formationis not new to the industry. Such operations are disclosed in severalU.S. patents mentioned hereinafter and included in their entirety byreference such as: U.S. Pat. No. 5,287,741 entitled “Methods ofPerforating and Testing Wells Using Coiled Tubing”, issued Feb. 22, 1994to Schultz et al; U.S. Pat. No. 5,638,904 entitled “Safeguarded Methodand Apparatus for Fluid Communication Using Coiled Tubing, WithApplication to Drill Stem Testing”, issued Jun. 17, 1997 to Misselbrookand Sask; U.S. Pat. No. 6,520,255 entitled “Method and apparatus forstimulation of multiple formation intervals”, issued on Feb. 18, 2003 toRandy C. Tolman et al; U.S. Pat. No. 6,959,763 entitled “Method andapparatus for integrated horizontal selective testing of wells”, issuedon Nov. 1, 2005 to Hook and Ramsey; U.S. Pat. No. 6,675,892 entitled“Well Testing Using Multiple Pressure Measurements” issued on Jun. 13,2004 to Fikri Kuchuk, et al.; and Published U.S. Patent Application No.20070044960 entitled “Methods, systems and apparatus for coiled tubingtesting” published on Mar. 1, 2007 on behalf of John Lovell et al.

However a large percentage of wells currently on production or waitingto be studied are sufficiently depleted or the damage is so extensivethat the reservoir pressure is not enough to drive the flow of formationfluids out to surface by itself in adequate volumes (if any at all) toperform a representative test.

The present invention aims to describe an apparatus and a method fortesting wells that have, without assistance, insufficient reservoirdrive to enable sufficient fluid flow to surface as to generate enoughinformation in order to representatively test the well.

SUMMARY OF THE INVENTION

The present invention comprises an apparatus for measuring a property ofa formation comprising a coiled tubing unit having one or more downholesensors capable of being lowered into a wellbore, a submersible pumpcapable of being lowered into a wellbore by the coiled tubing unit,means to power the submersible pump and a packer lowered into thewellbore by the coiled tubing unit to isolate a formation of interest.The apparatus may further comprise surface well testing equipmentcapable of measuring flow rate data, means for transmitting the sensormeasurements to a server capable of collecting, storing, andretransmitting the measured data, and means for transmitting themeasurements to a processing unit capable of calculating the propertiesof the formation.

The apparatus of the present invention includes at least one sensor tobe lowered into the wellbore by the coiled tubing unit, wherein thesensors are selected from a group of sensors that measure pressure,temperature, flowrate, spectroscopy, viscosity, H2S concentration, CO2concentration, bubble count, a dielectric property, gas/oil ratio,water/gas ratio, water/oil ratio and gamma ray radiation.

The apparatus of the present invention includes a submersible pump. Thesubmersible pump may be powered by a submersible pump cable lowered fromsurface along with the coiled tubing. The submersible pump cable may ormay not be clamped to the outside of the coiled tubing along its length.The submersible pump cable may or may not be clamped to the coiledtubing as the coiled tubing is lowered into a wellbore. If thesubmersible pump cable is to be clamped to the coiled tubing as it islowered into the wellbore, a work window device designed to be deployedtogether with the coiled tubing pressure control equipment that allowsaccess to both the coiled tubing and the submersible pump cable may beused. The work window can be closed to preserve pressure integrity ofthe surface pressure control system when desired. The submersible pumpcable may or may not be deployed through a stuffing box to preservepressure integrity of the surface pressure control system.

In one embodiment of the present invention, a packer is located belowthe submersible pump. The packer may be a straddle type packer, whereinthe straddle packer has a pup joint in between that allows fluid fromthe outside to enter the pup joint. The pup joint that allows fluid fromthe outside to enter the pup joint may be a perforated or slotted pupjoint situated in between the straddle packer.

An alternate apparatus of the present invention may have one packer andfurther comprise a pup joint that allows fluid from the outside to enterthe pup joint and a swab cup or flow restrictor assembly below the pupjoint.

The apparatus has at least one sensor located inside the joint below thepacker or located inside the joint above the pup joint in between thestraddle packer that allows fluid to enter. The sensors are selectedfrom a group of sensors that measure pressure, temperature, flowrate,spectroscopy, viscosity, H2S concentration, CO2 concentration, bubblecount, a dielectric property, gas/oil ratio, water/gas ratio, water/oilratio and gamma ray radiation.

In one embodiment, the apparatus may have at least one pressure andtemperature sensor located in the submersible pump. A safety valve maybe located above the submersible pump and an emergency release sub mayalso be located above or below the submersible pump.

The present invention also comprises a method of servicing a hydrocarbonwell using one or more sensors, a packer or straddle packer and asubmersible pump all lowered on coiled tubing into a well thatpenetrates a formation; and surface well testing equipment, thatincludes determining a property of a formation while flowing the wellassisted by the submersible pump and using flow data measured using thesurface well testing equipment integrated with pressure data measuredusing the one or more sensors lowered into the well penetrating theformation on the coiled tubing; treating the formation by pumping fluidinto the formation using the coiled tubing; and repeating thedetermining a property of a formation while flowing the well assisted bythe submersible pump and using flow data measured using the surface welltesting equipment integrated with pressure data measured using the oneor more sensors lowered into the well penetrating the formation on thecoiled tubing; wherein the coiled tubing remains deployed within thewell throughout the determining, treating, and repeating the determiningprocesses. The method of servicing a hydrocarbon well described abovemay resolve a property of the formation determined while flowing thewell assisted by the submersible pump and using flow data measured usingthe surface well testing equipment integrated with pressure datameasured using the one or more sensors lowered into the well penetratingthe formation on the coiled tubing; which may be included within areport that is created prior to treating the formation by pumping fluidinto the formation using the coiled tubing

A further embodiment of the present invention is a method of servicing ahydrocarbon well as described above wherein one or more processparameters in the treatment process of the formation by pumping fluidinto the formation using the coiled tubing is determined based ondetermining a property of a formation while flowing the well assisted bythe submersible pump and using flow data measured using the surface welltesting equipment integrated with pressure data measured using the oneor more sensors lowered into the well penetrating the formation on thecoiled tubing.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention is illustrated by way of example and not intendedto be limited by the figures of the accompanying drawings in which likereferences indicate similar elements and in which:

FIG. 1 shows an example embodiment of the present invention.

FIG. 2 shows an example embodiment of the present invention wherein thewellhead surface equipment rig up and a detail of the work window isshown.

FIG. 3 shows one embodiment of the present invention's assembly thatmight be lowered into a wellbore for testing a formation.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 shows an exemplary embodiment of the present invention, wherein acoiled tubing unit 10, lowers into a wellbore a submersible pump 15 viacoiled tubing 14. Below the submersible pump 15 a packer 16 is activatedto isolate a particular formation to be tested. As used herein, the term“packer” can also alternatively refer to swab cup or seal cup assembliesthat serve the same purpose of isolating regions on opposing sides ofthe packer. The submersible pump 15 is activated to assist fluid fromthe formation to flow in sufficient quantity as to test the formation. Aset of sensors 17 is integrated into the bottomhole assembly of thecoiled tubing. A submersible pump cable spooling unit 12 feeds thesubmersible pump cable 18 through a T sub 19 located in the surfacepressure equipment 20, the submersible pump cable 18 is clamped to thecoiled tubing 14 using a work window 13 to access both the coiled tubing14 and the submersible pump cable 18. One or more properties of theformation are measured by the sensors 17, such properties by way ofexample but not to limit this disclosure are pressure, temperature,flowrate, spectroscopy, viscosity, H2S concentration, CO2 concentration,bubble count, a dielectric property, gas/oil ratio, water/gas ratio,water/oil ratio and gamma ray radiation. The surface well testingequipment 11 measures flow rate data on the surface.

FIG. 2 shows an exemplary embodiment of the present invention, whereinmost of the surface pressure equipment is shown. The submersible pumpcable 22 enters the surface pressure equipment via a T sub, which may ormay not have means to control pressure such as a stuffing box, and it isaccessed through a work window 23. The work window 23 is used to accessthe coiled tubing 21 and the submersible pump cable 22 to be able toclamp the submersible pump cable to the coiled tubing 21 using a clamp24. The work window can be closed if and when desired, to preserve thepressure integrity of the surface pressure control equipment.

FIG. 3 depicts an exemplary embodiment of the present invention, whereinan example of a coiled tubing bottomhole assembly for the currentinvention is shown. The bottomhole assembly is lowered into the wellboreand positioned in place in front of the formation to be studied bycoiled tubing 30. The submersible pump cable 31 is lowered along withthe coiled tubing 30 to provide power to the submersible pump 32 and toallow communication between the sensors housed in the bottomholeassembly and the surface processing unit. The sensors may be housedabove, below or in the submersible pump. In the example shown in FIG. 3,the sensors 38 are housed in a pup joint above the joint 35 that isdesigned to allow fluid to enter the system. Joint 35 is designed toallow fluid to enter the system and it is often called a perforated orslotted pup joint. In the present example embodiment shown in FIG. 3, asafety valve 33 is deployed below the pump, the safety valve can beclosed if needed to restrict fluid from entering the coiled tubing. Thisis a common safety practice within the industry. Below the safety valve33, an emergency release sub 39 is depicted. A shear activated releasesub is commonly used. Its function is to release the assembly situatedabove the emergency release sub 39, should the operation need to do so(for example a stuck packer 34), from the assembly situated below theemergency release sub 39 hence freeing the coiled tubing 30 to beretrieved to surface. Also shown in FIG. 3 is a packer 34 to isolate theopen formation 36 to be tested, the packer 34 can be replaced by a swabcup or seal cup assembly. Below packer 34 are a series of joints, thenumber and length of joints will depend on the length of the openformation to be tested plus a predetermined extra length of joints toprovide a safety margin. Among these joints is a joint that allows fluidto enter the bottomhole assembly. To straddle the formation 36 to betested, a swab cup or seal cup assembly 37, as shown in FIG. 3, can beused; alternatively a second packer (i.e. a straddle packer, not shown)can be used replacing the shown swab cup assembly.

A person of ordinary skill in the art will recognize the use andfunctionality of surface pressure control equipment as a device or groupof devices designed to contain fluid under pressure inside a wellborewhile related equipment is moved in or out of the wellbore. Accordinglya person of ordinary skill in the art will recognize the use andfunctionality of a coiled tubing safety valve and a emergency releasesub. The first is a device to restrict fluid from entering the coiledtubing and the second device is used to release the assembly situatedabove the emergency release sub should the operation need to do so fromthe assembly situated below the emergency release sub.

While the invention is described through the above exemplaryembodiments, it will be understood by those of ordinary skill in the artthat modification to and variation of the illustrated embodiments may bemade without departing from the inventive concepts herein disclosed. Itwould be possible, for instance, to use a battery operated pump and awireless communication system to start the test; a fluid sample chambermay be lowered into the wellbore; seal cups or swab cup assemblies canbe used instead of packer or straddle packer; the position of thesensors, emergency release sub, packers, pup joints, safety valves, etccan vary in it relative position to each other and the amount thereofused in the string as described in the above exemplary embodiments.Accordingly, the invention should not be viewed as limited except by thescope of the appended claims.

1. An apparatus for measuring a property of a formation comprising: i. acoiled tubing unit having one or more downhole sensors capable of beinglowered into a wellbore; ii. a submersible pump capable of being loweredinto a wellbore by said coiled tubing unit; iii. means to power thesubmersible pump; and, iv. a packer lowered into said wellbore by saidcoiled tubing unit to isolate a formation.
 2. An apparatus as in claim1, further comprising surface well testing equipment capable ofmeasuring flow rate data.
 3. An apparatus as in claim 1, furthercomprising means for transmitting said sensors measurements to a servercapable of collecting, storing, and retransmitting the measured data. 4.An apparatus as in claim 1, further comprising means for transmittingthe measurements to a processing unit capable of calculating theproperties of the formation.
 5. An apparatus as in claim 1, wherein saidsensors are sensors from the group comprising pressure, temperature,flow, spectroscopy, viscosity, H2S, CO2, bubble count, dielectric,venturi, gas/oil ratio, water/gas ratio, water/oil ratio and gamma. 6.An apparatus as in claim 1, wherein said submersible pump is powered bya cable lowered from surface with the coiled tubing.
 7. An apparatus asin claim 6, wherein said submersible pump cable is clamped to theoutside of the coiled tubing and along its length.
 8. An apparatus as inclaim 7, wherein said cable is clamped to the coiled tubing as thecoiled tubing is lowered into a wellbore.
 9. An apparatus as in claim 7,wherein said cable is clamped to the coiled tubing through a work windowdevice designed to be deployed together with the coiled tubing surfacepressure control equipment that allows access to both the coiled tubingand the submersible pump cable; said work window can be closed topreserve pressure integrity of the surface pressure control system whendesired.
 10. An apparatus as in claim 6, wherein the submersible pumpcable is deployed through a stuffing box to preserve pressure integrityof the surface pressure control system.
 11. An apparatus as in claim 1,wherein the packer is located below the submersible pump.
 12. Anapparatus as in claim 1, wherein the packer is a straddle type packer.13. An apparatus as in claim 12, wherein the straddle packer has a pupjoint in between said straddle packer that allows fluid from the outsideto enter said pup joint.
 14. An apparatus as in claim 12, wherein thestraddle packer has a perforated or slotted pup joint in between saidstraddle packer.
 15. An apparatus as in claim 1, further comprising apup joint that allows fluid from the outside to enter said pup joint anda swab cup assembly below said pup joint.
 16. An apparatus as in claim 1or 12, wherein the packer is replaced by a swab cup assembly.
 17. Anapparatus as in claim 1, wherein at least one pressure sensor is locatedinside the joint below the packer.
 18. An apparatus as in claim 1,wherein at least one flow sensor is located inside the join below thepacker.
 19. An apparatus as in claim 1, wherein at least one Gas-OilRatio sensor is located inside the join below the packer.
 20. Anapparatus as in claim 1, wherein at least one temperature sensor islocated inside the join below the packer.
 21. An apparatus as in claim1, wherein at least one pressure sensor is located inside the jointabove the pup joint in between the straddle packer that allows fluid toenter.
 22. An apparatus as in claim 1, wherein at least one flow sensoris located inside the join above the pup joint in between the straddlepacker that allows fluid to enter.
 23. An apparatus as in claim 1,wherein at least one Gas-Oil Ratio sensor is located inside the jointabove the pup joint in between the straddle packer that allows fluid toenter.
 24. An apparatus as in claim 1, wherein at least one temperaturesensor is located inside the joint above the pup joint in between thestraddle packer that allows fluid to enter.
 25. An apparatus as in claim1, where in at least one pressure and temperature sensor is located inthe submersible pump.
 26. An apparatus as in claim 1, wherein a safetyvalve is located above the submersible pump.
 27. An apparatus as inclaim 1, wherein an emergency release sub is located above thesubmersible pump.
 28. A method of servicing a hydrocarbon well using oneor more sensors, one or more packers, and a submersible pump, alllowered on coiled tubing into a well that penetrates a formation; andsurface well testing equipment, comprising: i. determining a property ofa formation while flowing the well assisted by said submersible pump andusing flow data measured using said surface well testing equipmentintegrated with pressure data measured using said one or more sensorslowered into said well penetrating said formation on said coiled tubing;ii. treating said formation by pumping fluid into said formation usingsaid coiled tubing; and iii. repeating said determining a property of aformation while flowing the well assisted by said submersible pump andusing flow data measured using said surface well testing equipmentintegrated with pressure data measured using said one or more sensorslowered into said well penetrating said formation on said coiled tubing;wherein said coiled tubing remains deployed within said well throughoutsaid determining, treating, and repeating said determining processes.29. A method of servicing a hydrocarbon well in accordance with claim28, wherein said property of said formation determined in process i) isincluded within a report that is created prior to process ii).
 30. Amethod of servicing a hydrocarbon well in accordance with claim 28,wherein one or more process parameters in said treatment process ii) isdetermined based on said property of said formation determined inprocess i).